In the oil and gas production industry, it is sometimes desirable to use pumps to assist in the production of fluids from a well. For example, there may be insufficient pressure in the formation around an older well to lift the formation fluids to the surface. In another situation, a heavy fluid may be introduced into a well to stop formation fluids flowing up the well. In order to put the well back into production, the heavy, “kill” fluid must be lifted from the well using a pump.
Rotary screw pumps, such as twin or triple screw pumps, are positive displacement pumps which use rotating screws to pressurise a fluid. Rotary screw pumps are known for their ability to pump multiphase fluids.
In addition, it is known that, to generate high differential pressures, a pump may be constructed with multiple pumping stages. The total pump differential pressure is the sum of the individual stage differential pressures. Similarly, compressors can be constructed with multiple compressor stages, in order to generate high pressures in gases. Multiple stage pumps generally have pumping stages of equal swept volume whereas multiple stage compressors generally have compression stages of decreasing swept volume. By swept volume it is meant, in the case of a multiple screw pump for example, the volume of fluid discharged from the stage discharge during one complete revolution of the screws. The distinction between multiple stage pumps and multiple stage compressors arises since liquids are nearly incompressible whereas gases are compressible.
A multiple stage twin screw pump is disclosed in U.S. Pat. No. 6,413,065. This document proposes a multiple stage downhole pump having multiple twin screw pumping modules connected in series.
U.S. Pat. No. 7,093,665 discloses another downhole multiple stage twin screw pump. This document discusses a problem with the pump assembly described in U.S. Pat. No. 6,413,065. It is said that, in situations where there is a low liquid content and a high gas content in the fluid, the amount of liquid present is insufficient to effectively seal the gaps between the screw threads and the rotor housing. As a consequence, the pump cannot maintain the pressure difference across the pump and the pump loses efficiency.
U.S. Pat. No. 7,093,665 then discloses a method of adapting a downhole pump such as the one described in U.S. Pat. No. 6,413,065 for use in wells having a high gas content. In one embodiment, a liquid trap and a supplementary liquid channel is provided to capture a portion of the liquid near the outlet of the multiple stage twin screw pump and return it to the intake of the multiple stage twin screw pump. In this way, the liquid seal around the twin pumping screws can be enhanced.
A multistage pump assembly is also described in our pending International patent application, WO2010/092320. In this assembly, a plurality of components are provided which comprise a plurality of pre-assembled pump modules including at least one twin screw pump module. An elongate sleeve for housing the components and securing means attachable or engagable with a portion of the elongate sleeve are also provided. The securing means are operable to fixedly retain the components within the sleeve.
These pump arrangements do not address a further problem which arises when pumps of this type are used to generate high pressures in a multiphase fluid, as is often desirable in oil and gas well pumping applications. Due to the compressibility of gas, the rate at which fluid is delivered from one pump stage to a subsequent pump stage in a multiple stage pump assembly is less than the rate at which the subsequent pump tries to draw fluid into its intake. Accordingly, the last pump stage starts “sucking” on the previous pump stages, and the pressure difference across the last pump stage increases. In fact, the pressure difference across the pump stages increases from the first to the last pump.
A high proportion of the pressure generation occurs in the final stage of the pump. Consequently, this area of the pump can become extremely hot, reducing running clearances and risking seizure. Accordingly, when the percentage of gas in the pumped fluid is high, a multiple stage rotary screw pump becomes very inefficient.
The prior art pumps do not address this issue and so can suffer from the problems of over-heating and seizure caused by the final pump stage performing most of the work when the pumped fluid is a multiphase fluid.
A multiple stage pump could be designed more like a compressor, with a progressive reduction in the swept volume of its stages. Such a multiple stage pump would have its stages tailored for a particular gas to liquid ratio. To illustrate this, consider an oil well producing a fluid at 100° C. and having the following composition:                Oil: 2000 bbls/day (318 m3/day)        Water: 2000 bbls/day (318 m3/day)        Gas: 1000 bbls/day (159 m3/day).        
Consider a four stage pump assembly with the following pressure requirements:                Intake pressure: 1000 psig (6.89 MPa)        Discharge pressure: 3000 psig (20.7 MPa).        
To share the work equally between the four stages of the pump assembly, each stage would need to pressurise the fluid by 500 psig (3.45 MPa) (ignoring the effect of fluid shrinkage on hydraulic hp). In order to do so, a multiple stage pump would have to have stages with the following swept volumes:
Stage 1
                Total intake volume: 5000 bbls/day (795 m3/day)        Assuming a negligible temperature rise through the pump, the liquid is incompressible and the gas behaves as an ideal gas. So, for the gas fraction:        Intake pressure=1000 psig (6.89 MPa)=1014.7 psia (7.00 MPa absolute)        Intake gas volume=1000 bbls/day (159 m3/day)        Discharge pressure=1500 psig (10.3 MPa)=1514.7 psia (10.4 MPa absolute),        Discharge gas volume=1014.7×1000/1514.7=669.9 bbls/day (107 m3/day)        Total discharge volume=4669.9 bbls/day (742 m3/day) (i.e. liquid plus discharge gas)Stage 2        Total intake volume=4669.6 bbls/day (742 m3/day)        Intake pressure=1500 psig (10.3 MPa)=1514.7 psia (10.4 MPa)        Intake gas volume=669.9 bbls/day (107 m3/day)        Discharge pressure=2000 psig (13.8 MPa)=2014.7 psia (13.9 MPa)        Discharge gas volume=1514.7×669.9/2014.7=503.6 bbls/day (80.1 m3/day)        Total discharge volume=4503.6 bbls/day (716 m3/day)Stage 3        Total intake volume=4503.6 bbls/day (716 m3/day)        Intake pressure=2000 psig (13.8 MPa)=2014.7 psia (13.9 MPa)        Intake gas volume=503.6 bbls/day (80.1 m3/day)        Discharge pressure=2500 psig (17.2 MPa)=2514.7 psia (17.3 MPa)        Discharge gas volume=2014.7×503.6/2514.7=403.5 bbls/day (64.2 m3/day)        Total discharge volume=4403.5 bbls/day (700 m3/day)Stage 4        Total intake volume=4403.5 bbls/day (700 m3/day)        Intake pressure=2500 psig (17.2 MPa)=2514.7 psia (17.3 MPa)        Intake gas volume=403.5 bbls/day (64.2 m3/day)        Discharge pressure=3000 psig (20.7 MPa)        Discharge gas volume=2514.7×403.5/3014.7=336.6 bbls/day (53.5 m3/day)        Total discharge volume=4336.6 bbls/day (689 m3/day)        
Accordingly, for these well fluid and pumping conditions, a perfectly matched pump would require rotor sets with the following swept volumes:                First stage: 5000.0 bbls/day (795 m3/day)        Second stage: 4669.6 bbls/day (742 m3/day)        Third stage: 4503.6 bbls/day (716 m3/day)        Fourth stage: 4403.5 bbls/day (700 m3/day)        
In this example the gas constitutes only 20% of the total fluid volume into the pump intake and the pressure rise is relatively modest, but the difference in ideal swept rotor volume is greater than 10% between the first and last stage. This highlights the significant impact that the gas to liquid ratio can have.
However, there is a significant problem with multiple stage pump assemblies having decreasing swept volumes for the pump stages, in that, if the well fluid gas to liquid ratio changes, the pump stages quickly become mismatched with the gas to liquid ratio. If the volume of gas increases, each stage throughout the pump attempts to draw more fluid than the preceding stages can deliver. The later stages effectively suck on the preceding stages and the preceding stages can therefore contribute little effective work. This is the same scenario as described above for a constant volume multiple stage pump. If, on the other hand, the volume of gas decreases, the fluid volume discharged from an initial stage would be higher than that scavenged by a subsequent stage. The pressure of the fluid between the stages would rise rapidly, causing the pump to hydraulically lock or burst the housing or seals.
When pumping fluids from subterranean hydrocarbon bearing formations, this problem associated with multiple stage pumps used to pressurise multiphase fluids is particularly hard to address because the hydrocarbon liquids are volatile, containing gas in solution, and, depending upon the pressure of the reservoir, may further contain a proportion of free gas. Indeed a hydrocarbon reservoir may produce oil as a liquid initially but, as production continues and the pressure of the reservoir falls below the “bubble point”, will later flow a mixture of oil and gas. Every oilfield and every well within a field will have unique properties, depending on the hydrocarbon fluids themselves and the pressure of the fluids at that spatial and chronological point in the reservoir. To match the swept volume of successive stages in a pump to the fluid properties of an individual well at a given point in time would require an almost infinite number of rotor sizes and an impractical number of well interventions to change the pump to one more suited to the current conditions.
U.S. Pat. No. 5,779,451 describes the problems encountered when a conventional single rotary screw pump is used to pump fluids having a high gas fraction. It explains that overheating and seizure can occur due to lack of cooling liquid and a greater amount of heat generation across the last thread of the screw. The document teaches an improved twin-screw pump for providing a large pressure boost to high gas-fraction inlet streams. The pump includes a housing having an internal rotor enclosure, the rotor enclosure having an inlet and an outlet and a plurality of rotors operably contained in the enclosure. Each rotor has a shaft and a plurality of threads affixed thereon, the rotors being shaped to provide a non-uniform volumetric delivery rate along the length of each rotor. In one embodiment, the rotors have a plurality of threaded pumping stages separated by unthreaded non-pumping chambers. The threads of each pumping stage may have a different screw profile to provide progressively decreasing inlet volumetric delivery rates from the inlet to the outlet of the rotor enclosure. It is said that this arrangement can pump high gas to liquid ratio fluids with improved power efficiency and without seizing.
The document further teaches modifications to allow the pump to pump incompressible fluids. To accommodate incompressible fluids, each of the inter-stage chambers can be connected to the outlet of the pump and may be connected to a pressure reservoir. So, excess liquid can be bled to the outlet or the pressure reservoir. Check valves prevent back-flow from the outlet to the chambers. The connections between the chambers and the outlet can have pumps in them to drive fluid to the outlet.
GB 2299832 teaches a similar arrangement to that described in U.S. Pat. No. 5,779,451. Two sets of threads are provided on a single rotor in a single pump housing. A bleed port with a pressure relief valve is provided between the two sets of threads to relieve the spike of liquid volume and pressure which occurs whenever the void fraction of the pumped fluid becomes zero. Bleed fluid may be discarded, drained to a sump for recycling, re-circulated directly to the inlet of the pump, or handled otherwise.
Neither of these disclosures addresses the problem of an uneven distribution of work in a multiple stage rotary screw pump, as discussed above.
A contradiction therefore exists, in that although a single stage rotary screw pump is well known to be useful for pumping multiphase fluids, a multiple stage screw pump is not well suited to pumping multiphase fluids because the work cannot be distributed evenly between the various stages of the pump.
For these reasons, pumps used for hydrocarbon extraction typically are either multiple stage centrifugal pumps, which do not fix the volumetric capacity of each stage, or positive displacement pumps having a single stage. This approach avoids the need to match the swept volume of the pump to the pumped fluid volumes at the conditions encountered at each stage throughout the pump.
However, centrifugal and single stage pumps are not without their problems. Centrifugal pumps in particular are unable to process fluids with a high percentage of free gas because the gas accumulates within the hubs of their impellors causing the pump to loose prime and cavitate, a condition commonly described as gas locking. Single stage rotary screw pumps cannot efficiently develop the high pressures required to pump fluid from deep hydrocarbon bearing formations. Accordingly, to date, most twin screw multiphase pumps have been used in surface applications that require only a relatively low boost pressure.
There remains a need for a pump assembly which can be used more reliably and efficiently to pump multiphase fluids.